World energy supplies are quite substantially impacted by the world's heavy oil resources. Indeed, heavy oil comprises 2,100 billion barrels of the world's total oil reserves. Processes for the economic recovery of these viscous reserves are clearly important.
Asphaltic, tar and heavy oil are typically in deposits near the surface with overburden depths that span a few feet to a few thousand feet. In Canada vast deposits of this oil are found in Athabasca, Cold Lake, Celtic, Lloydminster and McMurray reservoirs. In California heavy oil is found in the South Belridge, Midway Sunset, Kern River and other reservoirs.
In the large Athabasca and Cold Lake bitumen deposits oil is essentially immobile--unable to flow under normal natural drive primary recovery mechanisms. Furthermore, oil saturations in these formations are typically large. This limits the injectivity of a fluid (heated or cold) into the formation. Furthermore, many of these deposits are too deep below the surface to effectively and economically mine.
In-situ techniques for recovering viscous oil and bitumens have been the subject of much previous investigation and can be split into 3 categories: 1) cyclic processes involving injecting and producing a viscosity reducing agent; 2) continuous steaming processes which involve injecting a heated fluid at one well and displacing oil to another set of wells; and 3) a relatively new Steam Assisted Gravity Drainage process (SAGD) by R. M. Butler (U.S. Pat. No. 4,344,485).
Cyclic steam or solvent stimulation in these two reservoirs is severely hampered by the lack of any significant steam injectivity into the respective formations. Hence, in the case of vertical wells a formation fracture is required to obtain any significant injectivity into the formation. Some success with this technique has been obtained in the Cold Lake reservoir at locations not having any significant underlying water aquifer. However, if a water aquifer exists beneath the vertical well located in the oil bearing formation, fracturing during steam injection results in early and large water influx during the production phase. This substantially lowers the economic performance of wells. In addition, cyclic steaming techniques reduce the economic viability of the process. Clearly, steam stimulation techniques in Cold Lake and Athabasca deposits are severely limited.
Vertical well continuous steaming processes are not technically or economically feasible in very viscous bitumen reservoirs. Oil mobility is simply far too small to be produced from a cold production well as is done in California type of reservoirs. Steam injection from one well and production from a remote production well are not possible unless a formation fracture is again formed. Formation fractures between wells are very difficult to control and there are operational problems associated with fracturing in a controlled manner so as to intersect an entire pattern of wells. Hence, classical steam flooding, even in the presence of initial fluid injectively when artificially induced by a fracture, has significant limitations.
Steam Assisted Gravity Drainage (U.S. Pat. No. 4,344,485; Butler, 1982) describes a parallel set of horizontal wells spaced relatively close together. In this process both wells are pre-heated by conduction. As fluid between the wells warms, a pressure difference is applied between the upper and lower wells to drive the fluid from between the wells. A SAGD startup process has been described in detail (Edmunds, N. R. and Gittins, S. D.; CIM Paper No. 91-65). When steam breaks through at some point between the horizontal wells, the pressure difference disappears and large amounts of steam are produced from the lower well. At this point in the startup, temperature control at the wellhead begins and produced steam volumes are throttled, placing the rest of the startup process in a gravity dominated regime.
Steam begins to rise upwardly and spreads laterally along the length of the well. The process is completely governed by gravity due to the imposition of steam trap control. For long wells a complete formation of a steam chamber along the length of the wellbore may take several months--thereby reducing the effectiveness of the long wellbore.
Complicating this problem is a substantial impossibility of drilling two perfectly parallel horizontal wells--either from a tunnel or from the surface. It is more probable that the two wells will have some wavy characteristics (sinuosity). Hence, steam breakthrough is more likely to occur at the point of closest spacing of the two wells. A picture of the initial breakthrough looks like two very long horizontal wells (say 500 meters) with only 1 or 2 meters having steam communication. The steam chamber can now grow only slowly along the length of the well.
Therefore, what is needed is a method of forcing the steam/liquid communication zone between wells to grow laterally, during the startup phase, at a rate substantially faster than that obtained by pure gravity drainage.